In the oil and gas industry, sub-sea wells produce from subterranean rock reservoirs a commingled stream consisting primarily of hydrocarbon liquids, water, and gases. This flowing stream is generally produced to the top of the sea or oceans surface at pressures and temperatures well above the surface atmospheric conditions. The well's flowing stream obtains the energy represented by these temperatures and pressures from the geothermal heat of the earth, the earth's overburden mass applied to the trapped subterranean gases and liquids, as well as the overburden weight of the ocean water. In offshore production industry it is found that portions of the energy available in this flowing stream are lost due to the cooling of the sea water and friction losses from transporting the flowing stream from the subterranean well at the sea floor to the process facility at the top of the sea surface. These energy losses are due in part to the fluid friction induced in flow lines, pipelines, as well as the loss of heat from the flowing stream due to cooling by the surrounding ocean water and currents as the well's flowing stream progresses to the sea surface process facility through pipelines.
It is a well known phenomena that gas hydrates often form in pipelines containing flowing streams produced from subterranean wells. Gas hydrate formation has long presented a problem to the industry, as it often results in the plugging of the flowing streams conduits to the sea surface process facility. Many methods and apparatus have been designed to reduce the potential for gas hydrate formation in offshore and sub-sea flow conduits. These methods include the heating of flow lines with electrical methods, vacuum insulated conduits, flow lines and wellheads, to keep the well stream from cooling, the addition of chemicals to inhibit hydrate formation, and many combinations thereof.
The conventional separation of liquids from gases flowing from subterranean wells is achieved by reducing the pressure of the commingled flowing stream and allowing the liquids and gases to separate by density differences in process facilities at the surface of the sea. In some cases the density separator is proceeded by cyclonic devices to reduce the water and or gas volume prior to the stream entering the larger separator vessel. In the case of offshore oil and gas production the fluid and gas production from the subterranean well is produced to the surface of the ocean and separated through conventional separation equipment on a surface offshore platform, or process equipment on a floating process vessel. Once these process facilities sufficiently separate the gas, and water from the oil in these surface process facilities, the liquid hydrocarbon is transferred to storage tanks, and transduced to market via an oil pipeline or a ship. Of the three separated items, liquid hydrocarbons, gas, and water, only the liquid hydrocarbon historically has been amenable to rapid commercialization due to its smaller volume at ambient pressures. The water produced from hydrocarbon reservoirs typically has little commercial value as it is usually salty and contains various impurities not suitable for commercialization. The separated gas produced from said subterranean wells require much more processing or infrastructure to transduce to a market. Therefore, whilst the gas has commercial value it is often to far from the market, or will require further processing to make it transportable, and or will require significant cost to transport due to it's volume at ambient sea surface conditions. Conversely, when gas is exploited form said subterranean reservoirs the associate salt water produced is dumped into the sea, or in rare cases re-injected into subterranean reservoirs.
Currently, when hydrocarbons are discovered with sufficient or economic amounts of liquids, the oil or condensate is commercialized and the gas is flared to the atmosphere or re-injected to the subterranean reservoir to maintain the reservoirs energy to produce hydrocarbons and enhance the recovery of the liquid hydrocarbon from the reservoir. The associated salty water is again dumped in the sea or ocean and or reinjected below the sub-sea surface. When the gas produced from a subterranean well is in an area of the world close to market it is commercialized. More recently the capricious venting of the gas to the atmosphere is being reduced for safety and environmental reasons. Therefore, if a hydrocarbon reservoir is discovered where the flowing stream produced from the subterranean reservoir contains gas, and there is no close point of commercialization, the alternatives for the gas are; to vent it to the atmosphere, burn it at surface, build a cryogenic gas plant, known as a liquid natural gas plant, LNG, for liquid storage and transport or re-inject it into the reservoir.
The gas separated from the flowing stream is often burned to generate power for the facilities electrical and heating needs, or re-injected into the subterranean reservoirs through a system of compressors, and conduits proceeding from the platform to the sub-sea well, or be compressed and transduced into gas pipelines. Conversely, the gas can be flared to the atmosphere. The injection of gas into the reservoir is difficult in many offshore areas owing to the very large pressures that the gas must be compressed to. This gas injection pressure required is a function of the distance the sub-sea well is from the sea surface process facility and compression station, as well as a function of the subterranean well depth in the sea and depth in the earth's surface. That is, the increased energy required to move the gas large distances in gas pipeline increase the energy required to compress the gas, and the pressure the gas must be compressed to must be more than the subterranean reservoir pressure that it is to be injected to. The subterranean reservoir pressure is typically a function of the depth below the sea. Hence the gas injection pressures to the reservoir increase as the distance from the surface process facility increases.
Likewise, the water produced from the subterranean well and separated by the surface process facility can be injected into the subterranean reservoir by a system of pumps and conduits proceeding from the surface facility down to the well and into the reservoir. Conversely the water can be dumped into the sea at surface. In either case, the separated water and gas must be either dumped to the atmosphere or reinjected if a commercialization point is not available. Unlike oil, gas can not be stored in a low-pressure vessel of a relatively small size, nor can gas be transported to market by a conventional ship. And unlike oil or gas salty water even when near populated areas has no commercial value.
U.S. Pat. No. 5,536,893 discloses a method to transport or store gas by conversion of a gas to a gas hydrate. In the U.S. Pat. No. 5,536,893 case the gas is pressurized after being purified and separated from the water and oil produced from the subterranean wells. Hence U.S. Pat. No. 5,536,893 discloses a method to create hydrates from an already processed gas. It does not teach the art of using the energy available from the wells at the sub-sea node to operate or power process equipment, nor does it teach the generation of hydrates below the sea level.
In some conditions, for example 3000-ft of water depth or more offshore, the well fluids and gases produced from subterranean depth reach the seafloor at pressures and temperatures higher than the surrounding sea floor environment. This condition clearly represents available energy to perform work, and can be exploited by those familiar with thermodynamic methods, for example Stirling cycle engines and refrigeration devices can easily be operated on these temperature differentials, to power and drive processes at the seafloor. The colder ambient temperatures of the seawater enhance the creation of gas hydrates in the flow stream in well heads, sub-sea flow lines and pipelines. These gas hydrates are a combination of water and gas forming a crystalline structure that encapsulates gas inside of the crystalline structure of hydrogen bonded molecules. The overall appearance is much like ice. The gas hydrate is often referred to in the literature as a clathrate hydrate of natural gas. The uncontrolled formation of hydrates in hydrocarbon processes results in the precipitation of the hydrates in flow steam of wells and sub-sea pipelines, and the literature teaches many methods and art in reducing the formation of hydrates in the oil and gas production industry. This precipitation becomes a significant impediment to the flow of the produced fluids and gases, and can completely stop the flow from the well at subterranean depths, in pipeline, process equipment, or other production equipment. Another interesting phenomena of the gas clathrate formation is that it separates the salt from the produced water such that the resulting crystal structure is a fresh water lattice encapsulating the gas. Hence the phenomena naturally separates from salt water the fresh water in a solid structure.
One method used to reduce the impediment to flow that the hydrate precipitation can produce is to inject into the stream chemicals that inhibit the hydrate formation in the sub-sea wells, wellheads, manifolds, and pipelines. This inhibition has been done with methanol, glycol, and other chemicals.
It has also been shown that insulating the flow lines and pipelines of flowing fluid streams in the sub-sea environment can reduce the hydrate formation in the flow stream. This has been done using different types of insulation techniques like vacuum-jacketed pipelines, coated pipelines and insulated jackets, etc. Other methods of reducing the affect of the cold ambient conditions sub-sea on the flowing stream have been used such as heating the pipeline with chemical or electrical heating methods.
Conventionally in the oil and gas industry, the pressure in the production fluids and gases is dissipated during the separation, storage, and transport phase. This is done as the higher pressures presents safety problems for storage vessels and transport lines as well as requiring expensive high-pressure storage and transport equipment. This problem of handling high-pressure gases in conventional oil and gas process equipment is further complicated by chemical corrosion in storage and transport equipment. That is, the combination of gases and water in the flowing stream can cause corrosion of process equipment, pipelines, and storage vessels. Also the combination of gasses, and water can cause the precipitation of scales that can cause plugging of equipment.